UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
----------------------
(Mark One)
X Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1999
Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission file number 33-93722
---------------------------
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2815171
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
5100 Tennyson Parkway
Suite 3000
Plano, TX 75024
(Address of principal (Zip code)
executive offices)
Registrant's telephone number, including area code:(972) 673-2000
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ____
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at October 31, 1999
----- ----------------------------------
Common Stock, $.001 par value 45,646,968
<PAGE>
DENBURY RESOURCES INC.
INDEX
Part I. Financial Information Page
Item 1. Financial Statements
Condensed Consolidated Balance Sheets at September 30, 1999
(Unaudited) and December 31, 1998 3
Condensed Consolidated Statements of Operations for
the Three and Nine Months ended September 30, 1999
and 1998 (Unaudited) 4
Condensed Consolidated Statements of Cash Flows for the
Nine Months ended September 30, 1999 and 1998 (Unaudited) 5
Notes to Condensed Consolidated Financial Statements 6-8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 9-21
Item 3. Quantitative and Qualitative Disclosures about
Market Risk 21
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 22
Signatures 23
2
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands of U.S. dollars except share amounts)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------ ------------
(Unaudited)
Assets
<S> <C> <C>
Current assets
Cash and cash equivalents $ 6,449 $ 2,049
Accrued production receivable 13,291 5,495
Trade and other receivables 4,538 16,390
------------ ------------
Total current assets 24,278 23,934
------------ ------------
Property and equipment (using full cost accounting)
Oil and gas properties 564,578 508,571
Unevaluated oil and gas properties 50,519 65,645
Less accumulated depreciation and depletion (410,694) (393,552)
------------ ------------
Net property and equipment 204,403 180,664
------------ ------------
Other assets 10,758 8,261
------------ ------------
Total assets $ 239,439 $ 212,859
============ ============
Liabilities and Stockholders' Equity (Deficit)
Current liabilities
Accounts payable and accrued liabilities $ 10,655 $ 13,570
Oil and gas production payable 6,748 5,118
------------ ------------
Total current liabilities 17,403 18,688
------------ ------------
Long-term liabilities
Long-term debt 152,500 225,000
Provision for site reclamation costs 1,618 1,436
Other liabilities 514 -
------------ ------------
Total long-term liabilities 154,632 226,436
------------ ------------
Stockholders' equity (deficit)
Preferred stock, $.001 par value, 25,000,000
shares authorized; none issued and outstanding - -
Common stock, $.001 par value, 100,000,000
shares authorized; 45,646,968 and 26,801,680
shares issued and outstanding at September
30, 1999 and December 31, 1998, respectively 46 27
Paid-in capital in excess of par 327,552 227,769
Accumulated deficit (260,194) (260,061)
------------ ------------
Total stockholders' equity (deficit) 67,404 (32,265)
------------ ------------
Total liabilities and stockholders'
equity(deficit) $ 239,439 $ 212,859
============ ============
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
3
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
(Unaudited - U.S. dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
1999 1998 1999 1998
--------- -------- -------- ---------
<S> <C> <C> <C> <C>
Revenues
Oil, gas and related product
sales $ 22,040 $ 19,263 $ 54,601 $ 66,959
Interest and other income 338 336 1,069 1,078
--------- -------- -------- ---------
Total revenues 22,378 19,599 55,670 68,037
--------- -------- -------- ---------
Expenses
Production 7,881 6,819 20,223 22,782
General and administrative 1,773 1,543 5,333 4,996
Interest 3,492 4,419 12,170 12,788
Depletion and depreciation 6,704 9,070 17,649 37,528
Franchise taxes 124 171 428 603
Writedown of oil and gas
properties - - - 165,000
--------- -------- -------- ---------
Total expenses 19,974 22,022 55,803 243,697
--------- -------- -------- ---------
Income (loss) before income taxes 2,404 (2,423) (133) (175,660)
Income tax benefit - - - 50,618
--------- -------- -------- ---------
Net income (loss) $ 2,404 $ (2,423) $ (133) $(125,042)
========= ======== ======== =========
Net income (loss) per common share
Basic $ 0.05 $ (0.09) $ 0.00 $ (4.88)
Diluted 0.05 (0.09) 0.00 (4.88)
Average number of common shares
outstanding
Basic 45,587 26,743 38,001 25,631
Diluted 45,589 26,895 38,085 26,037
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
4
<PAGE>
DENBURY RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of U.S. dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------
1999 1998
---------- ---------
<S> <C> <C>
Cash flow from operating activities:
Net loss $ (133) $(125,042)
Adjustments needed to reconcile to net cash flow
provided by operations:
Depreciation, depletion and amortization 17,649 37,528
Writedown of oil and gas properties - 165,000
Deferred income taxes - (50,618)
Other 1,126 456
---------- ---------
18,642 27,324
Changes in working capital items relating to
operations:
Accrued production receivable (7,796) 1,416
Trade and other receivables 11,852 1,987
Other assets (1,798) -
Accounts payable and accrued liabilities (2,915) (8,591)
Oil and gas production payable 1,630 1,145
---------- --------
Net cash provided by operations 19,615 23,281
---------- --------
Cash flow used for investing activities:
Oil and gas expenditures (22,281) (80,222)
Acquisition of oil and gas properties (18,995) (13,460)
Net purchases of other assets (1,109) (908)
Disposition of oil and gas properties 395 -
---------- --------
Net cash used for investing activities (41,990) (94,590)
---------- --------
Cash flow from financing activities:
Bank repayments (100,000) (200,000)
Bank borrowings 27,500 50,000
Issuance of senior subordinated debt - 125,000
Issuance of common stock 99,802 94,657
Costs of debt financing - (3,402)
Other (527) (22)
---------- --------
Net cash provided by financing activities 26,775 66,233
---------- --------
Net increase (decrease) in cash and cash equivalents 4,400 (5,076)
Cash and cash equivalents at beginning of period 2,049 9,326
---------- --------
Cash and cash equivalents at end of period $ 6,449 $ 4,250
========== ========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 9,813 $ 11,374
========== ========
</TABLE>
(See accompanying notes to Condensed Consolidated Financial Statements)
5
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Interim Financial Statements
The accompanying condensed consolidated financial statements of Denbury
Resources Inc. (the "Company" or "Denbury") have been prepared in accordance
with generally accepted accounting principles and pursuant to the rules and
regulations of the Securities and Exchange Commission. These financial
statements and the notes thereto should be read in conjunction with the
Company's annual report on Form 10-K for the year ended December 31, 1998. Any
capitalized terms used but not defined in these Notes to Condensed Consolidated
Financial Statements have the same meaning given to them in the Form 10-K.
Accounting measurements at interim dates inherently involve greater
reliance on estimates than at year end and the results of operations for the
interim periods shown in this report are not necessarily indicative of results
to be expected for the fiscal year. In the opinion of management of Denbury, the
accompanying unaudited condensed consolidated financial statements include all
adjustments (of a normal recurring nature) necessary to present fairly the
consolidated financial position of the Company as of September 30, 1999 and the
consolidated results of its operations for the three and nine months ended
September 30, 1999 and 1998 and its cash flow for the nine months ended
September 30, 1999 and 1998.
2. NET INCOME (LOSS) PER COMMON SHARE
Basic net income (loss) per common share is computed by dividing net income
or loss by the weighted average number of shares of common stock outstanding
during the period. Diluted net income (loss) per common share is calculated in
the same manner but also considers the impact on net income and common shares
for the potential dilution from stock options, stock warrants, and any other
convertible securities outstanding. For the three and nine month periods ended
September 30, 1999 and 1998, there were no adjustments to net income for
purposes of calculating diluted net income (loss) per common share. The
following is a reconciliation of the weighted average common shares used in the
basic and diluted net income (loss) per common share calculations for the three
and nine month periods ended September 30, 1999 and 1998 (shares in thousands).
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1999 1998 1999 1998
-------- -------- ------- --------
<S> <C> <C> <C> <C>
Weighted average common
shares - basic 45,587 26,743 38,001 25,631
Potentially dilutive securities:
Stock options 2 123 84 361
Stock warrants - 29 - 45
-------- -------- ------- --------
Weighted average common
shares - diluted 45,589 26,895 38,085 26,037
======== ======== ======= ========
</TABLE>
Due to the losses incurred by the Company for the nine months ended
September 30, 1999, and for the three and nine months ended September 30, 1998,
any dilutive effect from stock options and stock warrants would be antidilutive
to the calculation of diluted net income (loss) per common share and therefore
are excluded from the calculation for those periods.
6
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
----------- ---------
(Amounts in thousands)
(Unaudited)
<S> <C> <C>
9% Senior Subordinated Notes Due 2008 $ 125,000 $ 125,000
Senior bank loan 27,500 100,000
----------- ---------
Total long-term debt $ 152,500 $ 225,000
=========== =========
</TABLE>
4. CHANGE TO UNITED STATES GAAP; DIFFERENCES IN GAAP BETWEEN UNITED STATES
AND CANADA
In April 1999, the Company moved its corporate domicile from Canada to the
United States as a Delaware corporation (see Note 5). As a result of this move,
the consolidated financial statements for all periods have been prepared in
accordance with United States GAAP rather than Canadian GAAP. For the periods
presented herein, there are not any differences between United States and
Canadian GAAP. Historically, the Company has had differences between the two
accounting methods in the areas of diluted earnings per share, the handling of
losses on the early extinguishment of debt and the guidelines regarding full
cost ceiling tests.
5. 1999 SALE OF EQUITY AND MOVE OF DOMICILE
At a special meeting of the stockholders held on April 20, 1999, the
stockholders approved (i) a move of the Corporate's domicile from Canada to the
United States as a Delaware corporation, (ii) the sale of 18,552,876 common
shares to an affiliate of the Texas Pacific Group ("TPG") for $100 million or
$5.39 per share, and (iii) increases in the number of shares available for
issuance under the Company's stock purchase and stock option plans. The move of
domicile was completed on April 21, 1999, and along with the move, the Company's
wholly-owned subsidiary, Denbury Management Inc. ("DMI"), was merged into the
new Delaware parent company, Denbury Resources Inc. This move of domicile did
not have any effect on the operations and assets of the Company, and as part of
the move and merger, Denbury Resources Inc. expressly assumed any and all
liabilities of its subsidiary, DMI, including DMI's obligation for the 9% Senior
Subordinated Notes due 2008 and DMI's outstanding bank credit facility. The
December 31, 1998 year-end balance sheet included herein has been modified to
reflect the capital structure of the Company after the move of domicile even
though this transaction occurred after the balance sheet date.
The sale of common stock to TPG was also completed on April 21, 1999. As a
result of this equity transaction, TPG's pro-rata ownership of the outstanding
common stock of the Company increased from 32% to 60%. The Company intends to
use the proceeds from the equity sale for acquisitions, although in the interim,
the funds have been used to reduce its outstanding bank debt.
6. PRODUCT PRICE HEDGING CONTRACTS
During the first quarter of 1999, the Company collected $539,000 on two
no-cost financial contracts ("collars") that hedged a total of 40 million cubic
feet of natural gas per day ("MMcf/d"), the last of which expired in August
1999. In December 1998 the Company purchased a natural gas hedge for the period
of July 1999 through December 2000 which consists of a no-cost collar with a
floor price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu. This
contract hedged 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d
for each month thereafter. In
7
<PAGE>
DENBURY RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 1999, the Company retired 4 MMcf/d of the 30 MMcf/d of this contract
for the months of November 1999 through March 2000 at a cost of approximately
$312,000. For some periods, this contract covers over 100% of the Company's
current net natural gas production. During the third quarter of 1999, the
Company paid $370,000 on these contracts, resulting in a net year to date out of
pocket cost of $80,000 on the natural gas hedges, including the cost of the
buyout in September. Based on the futures market prices at September 30, 1999,
the Company would expect to pay approximately $1.7 million on these commodity
contracts during the remaining term because certain futures market prices at
September 30, 1999 exceeded the ceiling on the contract collars.
During the fourth quarter of 1998, the Company also modified certain of its
oil sales contracts. The new contracts, which are generally for a period of
eighteen months, provide that approximately 1/3 of the Company's oil production
as of September 30, 1999, has a price floor of between $8.00 and $10.00 per Bbl.
This equates to a NYMEX oil price of between $15.00 and $16.00 per Bbl. As
compensation for the price floors, the contracts provide that the Company's
discount to NYMEX increases as oil prices rise.
During March and April 1999, the Company entered into two collars to hedge
a portion of its oil production. The first contract was a fixed price swap for
3,000 Bbls/d for the period of April through December, 1999 at a price of $14.24
per Bbl. The second contract was a collar to hedge 3,000 Bbls/d for the period
of May, 1999 through December, 2000 with a floor price of $14.00 per Bbl and a
ceiling price of $18.05 per Bbl. The Company paid approximately $540,000 and
$3.4 million on these contracts during the second and third quarters
respectively, which lowered the effective net oil price received by the Company
during those periods by $0.51 and $2.95 per barrel, respectively. These two oil
financial contracts hedge slightly less than 45% of the Company's current oil
production. Based on the futures market prices at September 30, 1999, the
Company would expect to pay approximately $8.1 million over the remaining terms
of the oil hedge contracts.
In the aggregate, the Company paid a net amount of $4.1 million during the
first nine months of 1999 on its commodity hedges. For further discussion
regarding the Company's derivative financial instruments, see "Market Risk
Management" in Management's Discussion and Analysis of Financial Condition and
Results of Operations.
8
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following should be read in conjunction with the Company's financial
statements contained herein and in the Form 10-K for the year ended December 31,
1998, along with Management's Discussion and Analysis contained in such Form
10-K. Any capitalized terms used but not defined in the following discussion
have the same meaning given to them in the Form 10-K.
Denbury is an independent energy company engaged in acquisition,
development and exploration activities in the U.S. Gulf Coast region, primarily
onshore in Louisiana and Mississippi. The Company's growth in proved reserves,
production and cash flow over the years has been achieved by concentrating on
the acquisition of properties which it believes have significant upside
potential and through the efficient development, enhancement and operation of
those properties.
SIGNIFICANT 1999 EVENTS
1999 SALE OF EQUITY AND MOVE OF DOMICILE. At a special meeting of the
stockholders held on April 20, 1999, the stockholders approved (i) a move of the
Corporate's domicile from Canada to the United States as a Delaware corporation,
(ii) the sale of 18,552,876 common shares to an affiliate of the Texas Pacific
Group ("TPG") for $100 million or $5.39 per share, and (iii) increases in the
number of shares available for issuance under the Company's stock purchase and
stock option plans. The move of domicile was completed April 21, 1999, and along
with the move, the Company's wholly-owned subsidiary, Denbury Management Inc.
("DMI"), was merged into the new Delaware parent company, Denbury Resources Inc.
This move of domicile did not have any effect on the operations and assets of
the Company, and as part of the move and merger, Denbury Resources Inc.
expressly assumed any and all liabilities of its subsidiary, DMI, including
DMI's obligation for the 9% Senior Subordinated Notes due 2008 and DMI's
outstanding bank credit facility.
The sale of common stock to TPG was also completed on April 21, 1999. As a
result of this transaction, TPG's pro-rata ownership of the outstanding common
stock of the Company increased from 32% to 60%. The Company had approximately
45.6 million common shares outstanding as of September 30, 1999. The Company
intends to use the proceeds from the TPG equity sale for acquisitions, although
in the interim, the funds were used to reduce its outstanding bank debt.
FEBRUARY 1999 AMENDMENT TO BANK CREDIT FACILITY. On February 19, 1999, the
Company completed an amendment to its credit facility with Bank of America, as
agent for a group of eight other banks. This amendment set the borrowing base at
$110 million, of which $60 million was considered by the banks to be within
their normal credit guidelines. The credit facility continued with its other
restrictions, such as a prohibition on the payment of dividends and a
prohibition on most debt, liens and corporate guarantees. This amendment:
o provided certain relief on the minimum equity and interest coverage
tests;
o changed the facility to one secured by substantially all of the
Company's oil and natural gas properties;
o required that as long as the borrowing base is larger than a borrowing
base that conforms to normal credit guidelines (currently $60
million), that at least 75% of the funds borrowed subsequent to the
closing of the TPG purchase must be used for either qualifying
acquisitions or capital expenditures made to maintain, enhance or
develop its proved reserves ("Qualified Purpose"); and
o increased the interest rate to a range from LIBOR plus 1.0% to LIBOR
plus 1.75% (depending on the amounts outstanding) and LIBOR plus
2.125% on all debt if the outstanding debt exceeds the borrowing base
under normal credit guidelines, currently set at $60 million.
9
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
After the repayment of the credit facility in April, 1999 with the proceeds
from the sale of common stock to TPG, there was approximately $9.6 million
outstanding on the facility, leaving a total borrowing capacity at that time of
approximately $100 million. Since April, the Company has borrowed a total of
$17.9 million on this facility for two acquisitions, resulting in $27.5 million
of outstanding bank debt as of September 30, 1999. At the October 1, 1999
re-determination of the borrowing base, the conforming borrowing base of $60
million and the total borrowing base of $110 million were re-affirmed, leaving
the Company with a total borrowing capacity of $82.5 million as of October 1,
1999. The Company also made a slight modification to the bank agreement as of
September 30, 1999 which reduced from $25 million to $15 million the amount that
could be borrowed by the Company for expenditures other than a Qualified
Purpose. To date during 1999, all of the Company's borrowings have been for a
Qualified Purpose.
The next scheduled borrowing base re-determination will be as of April 1,
2000. There can be no assurance that the banks will not reduce the borrowing
base at that time, as such redetermination will depend on current and expected
oil and natural gas prices at that time, the Company's development and
acquisition results during 1999, the then current level of debt and several
other factors, some of which are beyond the Company's control.
CAPITAL RESOURCES AND LIQUIDITY
As a result of depressed oil prices in 1998 which continued into the first
part of 1999, the Company's cash flow and results of operations were
significantly adversely effected during 1998 and the first quarter of 1999. This
reduction in cash flow also contributed to an increase in the Company's debt
levels, which as a multiple of cash flow, were at historic highs as of March 31,
1999. Because of the downturn in the oil and gas industry during 1998, resulting
from the decreases in oil and natural gas prices, the Company sought additional
capital and in December 1998 entered into an agreement to sell $100 million of
common shares to TPG. This sale of equity was approved by stockholders on April
20, 1999 and closed on April 21, 1999 (see "1999 Sale of Equity and Move of
Domicile" above).
As a result of the equity infusion, the Company's bank debt was reduced by
$100 million and the Company's stockholders' deficit was eliminated. As of
September 30, 1999, the Company had positive stockholders equity of $67.4
million and $27.5 million of bank debt outstanding, leaving $82.5 million
available on the bank credit facility. In addition, oil prices have climbed from
a first quarter average NYMEX price of approximately $13.00 per Bbl to a third
quarter average NYMEX price of approximately $21.68 per Bbl. The Company's net
oil price has increased from a first quarter average of $9.22 per Bbl to a third
quarter average of $13.63 per Bbl. The Company's net oil price is less than the
NYMEX price due to several factors, including transportation costs, the average
gravity of the oil, the sulphur content and other factors. The net prices have
also been impacted by the effect of oil hedges, particularly in the third
quarter (see "Market Risk Management").
Both the improved product prices and the reduction of debt have had a
positive impact on the Company's earnings and cash flow for the second and third
quarters of 1999 and will continue to impact future periods. These prices will
allow the Company to pursue oil development opportunities that were uneconomical
at the low oil prices which prevailed in the second half of 1998 and first
quarter of 1999. However, there can be no assurance that the recent increase in
oil prices will be sustained. In addition, with the funds made available by the
equity sale to TPG, the Company intends to pursue oil and gas acquisitions
which, if accomplished, should also be accretive to the Company's operating
results. During the first nine months of 1999, the Company spent a total of
$19.0 million on acquisitions which were producing approximately 2,200 BOE/d as
of early October 1999. However, there can be no assurance that suitable
acquisitions will be identified in the future or that any such acquisitions will
be successful in achieving desired profitability objectives. Without suitable
acquisitions or the capital to fund such acquisitions, the Company's future
growth could be limited or even eliminated.
10
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
The Company's current development budget for 1999 has been increased
slightly to $38.5 million as a result of the improved product prices and the
addition of several development wells at Heidelberg scheduled for the latter
part of the fourth quarter. Preliminarily, the Company has budgeted
approximately $60 million for 2000, with a substantial portion of these
expenditures relating to facilities and workovers, with the majority to be spent
on the waterflood units at Heidelberg. Approximately 25% to 30% of the
preliminary 2000 budget relates to development drilling and an additional 10% of
the budget is devoted to exploratory drilling, seismic or other exploratory type
expenditures. However as in 1999, the general intent is to minimize the use of
the bank credit facility for anything other than acquisitions. Although the
level of the Company's projected cash flow is highly variable and difficult to
predict due to volatility in product prices, the success of its drilling and
developmental work and other factors, the Company does not expect its
development spending in either 1999 or 2000 to cause debt to increase
substantially. The Company also expects that this spending level should be
sufficient to cause a slight increase in production levels throughout the year
2000. Furthermore, if acquisitions are unavailable at attractive rates, the
Company does have an inventory of potential development projects that it could
commence, subject to the availability and allocation of capital resources.
SOURCES AND USES OF FUNDS
During the first three quarters of 1999, the Company spent approximately
$22.3 million on exploration and development expenditures and approximately
$19.0 million on acquisitions. The exploration and development expenditures
included approximately $3.3 million spent on drilling, $4.8 million on
geological, geophysical and acreage expenditures and $14.2 million on facilities
and workover costs. These expenditures were funded primarily by cash flow from
operations.
In contrast, during the first three quarters of 1998 the Company spent
approximately $80.2 million on oil and natural gas development expenditures and
approximately $13.5 million on acquisitions. The development expenditures
included approximately $48.7 million spent on drilling, $17.1 million on
geological, geophysical and acreage expenditures and $14.4 million spent on
facilities and workover costs. These expenditures were funded by cash flow from
operations and bank debt.
RESULTS OF OPERATIONS
Operating Income
Production volumes were lower on a BOE basis during both the three and nine
month periods ended September 30, 1999 when compared to the corresponding
periods in 1998. These declines in production are generally the result of the
curtailment in spending during the last half of 1998 after the decline in oil
prices, although production has increased each quarter during 1999.
Correspondingly, operating income was also less during the nine month period
ended September 30, 1999 as compared to the comparable period in 1998, although
increased oil prices over the past six months were sufficient to offset the
reduced production for the third quarter of 1999 when compared to the third
quarter of 1998. These statistics and other data are set forth in the following
chart.
11
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------- -------------------- ------------------
1999 1998 1999 1998
- --------------------------------- --------- -------- -------- -------
<S> <C> <C> <C> <C>
OPERATING INCOME (THOUSANDS)
Oil sales $ 15,673 $ 10,921 $ 36,649 $41,748
Natural gas sales 6,367 8,342 17,952 25,211
Less production taxes (1,139) (739) (2,568) (3,350)
Less lease operating expenses (6,742) (6,080) (17,655) (19,432)
--------- -------- -------- -------
Operating income $ 14,159 $ 12,444 $ 34,378 $44,177
--------- -------- -------- -------
UNIT PRICES
Oil price per barrel ("Bbl") $ 13.63 $ 9.30 $ 11.73 $ 10.64
Gas price per thousand cubic
feet ("Mcf") 2.54 2.28 2.33 2.35
NETBACK PER BOE (1):
Sales price $ 14.06 $ 10.79 $ 12.38 $ 11.73
Production taxes (0.73) (0.41) (0.58) (0.59)
Lease operating expenses (4.30) (3.41) (4.00) (3.40)
--------- -------- -------- -------
Production netback $ 9.03 $ 6.97 $ 7.80 $ 7.74
--------- -------- -------- -------
AVERAGE DAILY PRODUCTION VOLUME:
Bbls 12,500 12,764 11,449 14,373
Mcf 27,204 39,829 28,270 39,255
BOE 17,034 19,402 16,160 20,916
- --------------------------------- --------- -------- -------- -------
<FN>
(1) Barrel of oil equivalent using the ratio of one barrel of oil to 6 Mcf of
natural gas ("BOE").
</FN>
</TABLE>
Production for the third quarter of 1999 averaged 17,034 BOE/d, an increase
of 6% from the second quarter of 1999 rate of 16,013 BOE/d and an increase of
10% from the first quarter average of 15,417 BOE/d. The production levels in
1999 are less than the comparable periods in 1998 because production declined
each quarter during the last half of 1998 after spending was curtailed during
that period due to the low oil prices. This trend was reversed in 1999 with
improved oil prices.
During the third quarter of 1999, the Company realized approximately 900
BOE/d of additional production from its recent acquisitions at KingBee and
Little Creek Fields in Mississippi and should realize an additional production
increase in the fourth quarter of 1999 as the Little Creek Field was purchased
midway through the third quarter. The Company has also had production increases
throughout 1999 at its Heidelberg Field, primarily from the two waterflood
units. Activity on the East Heidelberg waterflood unit commenced in early 1998
and production on this unit has increased from approximately 250 Bbls/d in the
summer of 1998 to approximately 1,800 Bbls/d for the month of September, 1999.
The total production at Heidelberg averaged 6,140 BOE/d for the third quarter of
1999 as compared to 5,626 BOE/d for the prior quarter and 4,200 BOE/d for the
third quarter of 1998. The production increase in the third quarter represents
the seventh consecutive quarterly increase at this field since it was acquired
in late 1997. Production for this field averaged 2,900 BOE/d for the fourth
quarter of 1997 just prior to being acquired by Denbury.
Production during the third quarter of 1999 from the Company's other key
prior acquisition, the properties acquired from Amerada Hess in 1996, averaged
3,952 BOE/d. This compares to 4,081 BOE/d for the prior quarter and 7,600
12
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
BOE/d for the third quarter of 1998. The production on these properties peaked
in the second quarter of 1998 at 9,730 BOE/d and have declined since that time
due to normal production declines on horizontal oil wells drilled at Eucutta
Field in late 1997 and early 1998 and the lack of subsequent development work to
replace this production.
Oil and gas revenue for the nine month period ended September 30, 1999
decreased primarily as a result of the decrease in production when compared to
the comparable period in 1998. Although oil prices were approximately 10% higher
in the first nine months of 1999 as compared to 1998, they were not high enough
to offset the decrease in prodution. In general, oil prices gradually declined
throughout 1998 and did not begin to recover until late in the first quarter of
1999. In contrast, prices generally improved throughout 1999 resulting in a net
oil price that was 47% higher and a net average gas price that was 11% higher
for the third quarter of 1999 as compared to the third quarter of 1998. This
more than offset the 12% shortfall in overall production and as a result, the
oil and gas revenue was 14% higher for the third quarter of 1999 than the
comparable quarter in 1998. Included in the third quarter of 1999 net oil price
is a $3.4 million loss on oil hedging, which equates to approximately $2.95 per
Bbl. The majority of this loss relates to a 3,000 Bbls/d swap at $14.24 per Bbl
which ends in December 1999. The Company also realized a $370,000 loss on its
gas hedge and retired four MMBtu/d of its 30 MMBtu/d gas hedge for the period of
November 1999 through March 2000 during the third quarter at a total cost of
$312,000. The combined result of these two items lowered the net realized
natural gas price by approximately $0.27 per Mcf for the third quarter.
Production taxes and operating expenses decreased by $2.6 million or 11%
between the nine month periods ended September 30, 1999 and 1998 as a result of
cost saving measures, shutting-in certain wells and an overall decline in
production, all at least indirectly attributable to the decline in oil prices.
Approximately 30% of the decrease between these periods was attributable to a
decrease in production taxes which are primarily based on oil and natural gas
revenues. On a BOE basis, operating expenses increased for the nine month
periods due to the declines in production.
For the third quarter of 1999, production taxes and lease operating expense
increased by $1.1 million or 16% as compared to the third quarter of 1998. This
increase was a result of several wells being returned to production, an increase
of $400,000 in production taxes ($0.32 per BOE) and the addition of the Little
Creek Field during the third quarter of 1999 which has higher operating cost per
barrel because of the tertiary recovery operations. Operating expenses showed a
similar increase when comparing the third quarter of 1999 to the prior quarter.
For the properties acquired from Amerada Hess, the operating expenses declined
from the 1996 level of $5.35 per BOE to $3.39 per BOE for 1998, but increased to
$4.49 for the first nine months of 1999 as a result of the production declines.
Operating expense per BOE on the Heidelberg Field acquired from Chevron have
decreased from their initial level of $6.38 per BOE when acquired in late 1997
to an average of $5.04 per BOE during 1998 to an average of $4.97 per BOE for
the first nine months of 1999. These reductions result from general cost saving
measures and increased productivity per well through overall production
increases at Heidelberg.
General and Administrative Expenses
General and administrative ("G&A") expenses increased slightly as set forth
below:
13
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- -------------------------------- ------------------ -------------------
1999 1998 1999 1998
- -------------------------------- -------- -------- -------- --------
<S> <C> <C> <C> <C>
NET G&A EXPENSES (THOUSANDS)
Gross expenses $ 5,232 $ 4,631 $ 14,654 $ 14,382
State franchise taxes 124 171 428 603
Operator overhead charges (2,680) (2,455) (7,195) (7,375)
Capitalized exploration
expenses (779) (633) (2,126) (2,011)
-------- -------- -------- --------
Net expenses $ 1,897 $ 1,714 $ 5,761 $ 5,599
-------- -------- -------- --------
Average G&A cost per BOE $ 1.21 $ 0.96 $ 1.31 $ 0.98
Employees as of September 30 218 208 218 208
- -------------------------------- -------- -------- -------- --------
</TABLE>
Gross G&A expenses increased 13% between the third quarter of 1998 and 1999
and 2% between the first nine months of 1998 and 1999. When comparing the year
to date amounts, there were not any significant changes in either gross cost or
the amounts allocated as operator overhead. Generally, the Company was very
active during the first part of 1998 but then significantly reduced its field
expenditures and activity at the end of the second quarter of 1998 due to the
decline in oil prices. The activity level has gradually resumed in 1999,
beginning with the second quarter, as a result of the improved product prices.
Therefore the year-to-date comparison reveals only minor changes, although the
trend is significantly different. This difference is outlined when comparing the
respective third quarters, as there has been a 13% increase in gross cost in
1999 which is not quite offset by the 12% increase in the amounts recovered
through operators overhead charges or capitalization, resulting in a net
increase in G&A of 11% between the two periods. The single largest component of
the increase was the reinstatement of a bonus accrual in the third quarter of
1999 as no accrual was made during the last half of 1998 or the first half of
1999. There were also increased consultant fees in 1999 as a result of the
increased activity and increased rent expense as a result of increased space and
the expiration of an old lease in May 1999 which had below market rates.
As briefly discussed above, the net G&A is also affected by the amount of
overhead charged during the period. The respective well operating agreements
allow the Company, when it is the operator, to charge a well with a specified
overhead rate during the drilling phase and to also charge a monthly fixed
overhead rate for each producing well. As a result of the increased development
activity in the third quarter of 1999 as compared to the same period in 1998,
gross G&A recovered through these types of charges (listed in the above table as
"Operator overhead charges") was higher in the third quarter of 1999. During the
third quarter of 1998, approximately $2.5 million of gross G&A was recovered by
operator overhead charges, while during the third quarter of 1999 this recovery
increased to $2.7 million. On a BOE basis, G&A costs increased 26% from the
third quarter of 1998 to the comparable quarter in 1999 and increased 34% from
the first nine months of 1998 to the first nine months of 1999, primarily
because of decreased production on both an absolute and per well basis.
14
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Interest and Financing Expenses
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------ ------------------ -------------------
AMOUNTS IN THOUSANDS EXCEPT PER BOE
DATA 1999 1998 1999 1998
- ------------------------------------ -------- -------- --------- ---------
<S> <C> <C> <C> <C>
Interest expense $ 3,492 $ 4,419 $ 12,170 $ 12,788
Non-cash interest expense (205) (170) (612) (456)
-------- -------- --------- ---------
Cash interest expense 3,287 4,249 11,558 12,332
Interest and other income (338) (336) (1,069) (1,078)
-------- -------- --------- ---------
Net interest expense $ 2,949 $ 3,913 $ 10,489 $ 11,254
-------- -------- --------- ---------
Average net interest expense per BOE $ 1.88 $ 2.19 $ 2.38 $ 1.97
Average debt outstanding $147,363 $205,217 $ 178,585 $ 198,890
- ------------------------------------ -------- -------- --------- ---------
</TABLE>
In December 1997, the Company borrowed $202 million to fund the Chevron
Acquisition, resulting in $240 million of outstanding bank debt during January
and most of February 1998. On February 26, 1998 this debt was refinanced with
proceeds from the issuance of equity and subordinated notes, leaving a bank
balance of $40 million for the rest of the first quarter of 1998, plus $125
million of debt from the issuance of the subordinated notes. Borrowing increased
by $50.0 million during the second and third quarters of 1998 to fund $67.3
million of capital expenditures.
In 1999, the Company began the year with $225 million of total debt and
further increased this to $234.6 million by the end of the first quarter. This
debt was reduced in April 1999 by $100 million with the proceeds from the TPG
equity infusion (see "1999 Sale of Equity and Move of Domicile" above), although
an additional $17.9 million was borrowed during the remainder of the second
quarter and third quarter to fund acquisitions. The net result was a lower
average level of debt when comparing both the respective third quarters and the
year-to-date amounts for 1999 and 1998. The net effect on interest expense was a
decrease of 21% when comparing the third quarters of 1999 and 1998 and a
decrease of 5% when comparing the two nine month periods. On a BOE basis,
interest expense decreased only 14% for the comparable third quarter periods and
increased 21% for nine months periods as a result of the overall decline in
production.
Depletion, Depreciation and Site Restoration
The Company's depletion, depreciation and amortization ("DD&A") rate
dropped from $5.08 per BOE for the third quarter of 1998 and $6.57 for the first
nine months of 1998 to an average rate of $4.00 per BOE for the nine months
ended September 30, 1999. This resulted from an increase in the proved reserve
quantities since December 31, 1998 related to improved oil prices during 1999
and the reduced oil and gas property basis after the full cost pool writedowns
at June 30, 1998 and December 31, 1998. The DD&A rate for the first six months
of 1999 was $3.85 per BOE but was increased to a year to date average of $4.00
per BOE in the third quarter. The Company expects this rate to gradually
increase over time as most projects are expected to have a finding and
development cost in excess of $3.85 per BOE.
Under full cost accounting rules, each quarter the Company is required to
perform a ceiling test calculation. In determining the limitation on property
carrying values, U.S. accounting rules require the discounting of estimated
future net revenues from its proved reserves at 10% using constant current
prices following the guidelines of the Securities and Exchange Commission
("SEC"). Due to the higher product prices in 1999, the Company did not have any
ceiling
15
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
test limitations for any of the respective quarters. However, at June 30, 1998
and December 31, 1998, the Company incurred a $165 million and $115 million
writedown of oil and natural gas properties, respectively, primarily due to the
decline in oil prices during 1998.
The Company also provides for the estimated future costs of well
abandonment and site reclamation, net of any anticipated salvage, on a
unit-of-production basis. This provision is included in DD&A expense.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------- -------------------- ----------------
AMOUNTS IN THOUSANDS EXCEPT PER
BOE DATA 1999 1998 1999 1998
- --------------------------------- --------- -------- ------- -------
<S> <C> <C> <C> <C>
Depletion and depreciation $ 6,667 $ 8,984 $17,468 $37,254
Site restoration provision 37 86 181 274
--------- -------- ------- -------
Total amortization $ 6,704 $ 9,070 $17,649 $37,528
--------- -------- ------- -------
Average DD&A cost per BOE $ 4.28 $ 5.08 $ 4.00 $ 6.57
- --------------------------------- --------- -------- ------- -------
</TABLE>
Income Taxes
Due to a net operating loss of the Company for tax purposes, the Company
does not have any current tax provision. In addition, as a result of the net
pre-tax loss of $133,000 for the nine months ended September 30, 1999, an income
tax provision for that period using the effective tax rate of 37% would have
resulted in a $49,000 income tax benefit and an increase to the deferred tax
asset. Since the Company currently has a large tax net operating loss and it is
uncertain whether this total tax asset will ultimately be realized, the Company
has provided a valuation allowance for the tax benefit generated in the first
nine months of 1999, resulting in no effective income tax provision.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------- -------------------- -----------------
1999 1998 1999 1998
- --------------------------------- --------- -------- ------- --------
<S> <C> <C> <C> <C>
Deferred income tax benefit
(thousands) $ - $ - $ - $(50,618)
Average income tax costs
(benefit) per BOE - - - (8.86)
Effective tax rate - - - 29%
- --------------------------------- --------- -------- ------- --------
</TABLE>
Summary Operating and BOE Data
Net income increased during 1999 for both the third quarter and the first
nine months, when compared to 1998 as a result of improved operating results and
as a result of the $165 million writedown of oil and natural gas properties as
of June 30, 1998 . These and other factors are discussed in more detail above.
16
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------- ------------------ -----------------
AMOUNTS IN THOUSAND EXCEPT PER SHARE
AMOUNTS 1999 1998 1999 1998
- --------------------------------------- -------- -------- -------- ---------
<S> <C> <C> <C> <C>
Net income (loss) $ 2,404 $(2,423) $ (133) $(125,042)
Net income (loss) per common share:
Basic $ 0.05 $ (0.09) $ 0.00 $ (4.88)
Diluted 0.05 (0.09) 0.00 (4.88)
Cash flow from operations (1) $ 9,547 $ 6,817 $18,642 $ 27,324
- --------------------------------------- -------- -------- -------- ---------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
The following table summarizes the cash flow, DD&A and results of
operations on a BOE basis for the comparative periods. Each of the individual
components are discussed above.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------- ------------------- ---------------
Per BOE Data 1999 1998 1999 1998
- --------------------------------------- -------- -------- ------ -------
<S> <C> <C> <C> <C>
Oil and natural gas revenue $ 14.06 $ 10.79 $12.38 $ 11.73
Production taxes (0.73) (0.41) (0.58) (0.59)
Lease operating expenses (4.30) (3.41) (4.00) (3.40)
- --------------------------------------- -------- -------- ------ -------
Production netback 9.03 6.97 7.80 7.74
General and administrative (1.21) (0.96) (1.31) (0.98)
Net interest expense (1.88) (2.19) (2.38) (1.97)
Other 0.15 - 0.12 -
- --------------------------------------- -------- -------- ------ -------
Cash flow from operations(1) 6.09 3.82 4.23 4.79
DD&A (4.28) (5.08) (4.00) (6.57)
Deferred income taxes - - - 8.86
Writedown of oil and natural gas
properties - - - (28.90)
Other non-cash items (0.28) (0.10) (0.26) (0.08)
- --------------------------------------- -------- -------- ------ -------
Net income (loss) $ 1.53 $ (1.36) $(0.03) $(21.90)
- --------------------------------------- -------- -------- ------ -------
<FN>
(1) Represents cash flow provided by operations, exclusive of the net change in
non-cash working capital balances.
</FN>
</TABLE>
Market Risk Management
The Company uses fixed and variable rate debt to partially finance budgeted
expenditures. These agreements expose the Company to market risk related to
changes in interest rates. The Company does not hold or issue derivative
financial instruments for trading purposes. The carrying and fair value of these
debt instruments have not changed significantly since year-end. The Company also
enters into various financial contracts to hedge its exposure to commodity price
risk associated with anticipated future oil and natural gas production. These
contracts consist of price ceilings and floors, no-cost collars and fixed price
swaps.
During the first quarter of 1999, the Company collected $539,000 on two
no-cost financial contracts ("collars") that hedged a total of 40 million cubic
feet of natural gas per day ("MMcf/d"), the last of which expired in August
1999.
17
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
In December 1998 the Company purchased a natural gas hedge for the period of
July 1999 through December 2000 which consists of a no-cost collar with a floor
price of $1.90 per MMBtu and a ceiling price of $2.58 per MMBtu. This contract
hedged 25 MMcf/d for the months of July and August 1999 and 30 MMcf/d for each
month thereafter. In September 1999, the Company retired 4 MMcf/d of the 30
MMcf/d of this contract for the months of November 1999 through March 2000 at a
cost of approximately $312,000. For some periods, this contract covers over 100%
of the Company's current net natural gas production. During the third quarter of
1999, the Company paid $370,000 on these contracts, leaving a net year to date
out of pocket cost of $80,000 on the natural gas hedges, including the cost of
the buyout in September.
During the fourth quarter of 1998, the Company also modified certain of its
oil sales contracts. The new contracts, which are generally for a period of
eighteen months, provide that approximately 1/3 of the Company's oil production
as of September 30, 1999, has a price floor of between $8.00 and $10.00 per Bbl.
This equates to a NYMEX oil price of between $15.00 and $16.00 per Bbl. As
compensation for the price floors, the contracts provide that the Company's
discount to NYMEX increases as oil prices rise.
During March and April 1999, the Company entered into two collars to hedge
a portion of its oil production. The first contract was a fixed price swap for
3,000 Bbls/d for the period of April through December, 1999 at a price of $14.24
per Bbl. The second contract was a collar to hedge 3,000 Bbls/d for the period
of May, 1999 through December, 2000 with a floor price of $14.00 per Bbl and a
ceiling price of $18.05 per Bbl. The Company paid approximately $540,000 and
$3.4 million on these contracts during the second and third quarters
respectively, which lowered the effective net oil price received by the Company
during those periods by $0.51 and $2.95 per barrel, respectively. These two oil
financial contracts hedge slightly less than 45% of the Company's current oil
production.
In the aggregate, the Company paid a net amount of $4.1 million during the
first nine months of 1999 on its commodity hedges. These contracts in effect at
September 30, 1999 expire at various dates, with the latest being December 2000.
Gain or loss on these derivative commodity contracts would be offset by a
corresponding gain or loss on the hedged commodity positions. Based on the
futures market prices at September 30, 1999, the Company would expect to pay
approximately $8.1 million on the oil hedge contracts and pay approximately $1.7
million on the natural gas hedge contracts. If the futures market prices were to
increase 10% from those in effect at September 30, 1999, the Company would be
required to make additional cash payments under the commodity contracts of
approximately $7.1 million. If the futures market prices were to decline 10%
from those in effect as September 30, 1999, the Company would reduce the
payments due under the natural gas commodity contracts by $1.6 million and
reduce the payments due under the oil contracts by $3.6 million.
Year 2000 Update
Year 2000 issues relate to the ability of computer programs or equipment to
accurately calculate, store or use dates after December 31, 1999. These dates
can be handled or interpreted in a number of different ways, but the most common
error is for the system to contain a two digit year which may cause the system
to interpret the year 2000 as 1900. Errors of this type can result in system
failures, miscalculations and the disruption of operations, including, among
other things, a temporary inability to process transactions, send invoices or
engage in similar normal business. In response to the Year 2000 issues, the
Company developed a strategic plan divided into the following phases: inventory,
product compliance based on vendor representations and in-house testing, third
party integration and development of a contingency plan.
18
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
All of the Company's processing needs are handled by third party systems,
none of which have been substantially modified and all of which have been
purchased within the last few years. Therefore, the Company's initial review of
its in-house systems with regard to Year 2000 issues required an inventory of
its systems and a review of the vendor representations. The Company has
completed this initial review of its information systems. The licensor of the
Company's core financial software system has certified that such software is
Year 2000 compliant. Additionally, the remaining significant software systems,
various types of equipment and non-information technology have been reviewed,
and based on vendor representations and / or in-house testing, are either
compliant or are systems that are not date specific.
The Company's non-information technology consists primarily of various oil
and gas exploration and production equipment. The review of these systems has
established that the primary non-information technology systems functions are
either not date sensitive or are Year 2000 compliant based on vendor
representations, and are therefore predicted to operate in customary manners
when faced with Year 2000 issues. Furthermore, the Company has determined that
in the event such systems are unable to address the Year 2000, employees can
manually perform most, if not all, functions.
In anticipation of Year 2000 issues, the Company also evaluated the Year
2000 readiness status of its third party service suppliers. In addition to
reviewing Year 2000 readiness statements issued by the third parties handling
the Company's processing needs, to date the Company has received, and is relying
upon, Year 2000 readiness reports periodically issued by its financial services
and electrical service providers, vendors and purchasers of the Company's oil
and natural gas products. The Company, based on their representations, does not
currently foresee material disruptions in the Company's business as a result of
Year 2000 issues. Unanticipated prolonged losses of certain services, such as
electrical power, could cause material disruptions for which no economically
feasible contingency plan has been developed.
In addition to seeking vendor representations regarding their products, the
Company has also conducted limited in-house testing of its primary core systems
and non-information technology, and either all systems tested have adequately
addressed possible Year 2000 scenarios or the Company has a plan in place to
remedy or work around the deficiency. This remedy is not expected to cause any
material disruption in the Company's business or require any significant
increase in the time required to complete these funtions.
Although the effects of Year 2000 issues cannot be predicted with
certainty, the Company believes that the potential impact, if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or calculations, other than those which might occur in a "worst case"
scenario as described below, which the Company does not anticipate will occur.
After considering Year 2000 effects on in-house operations, the Company
does not expect that any additional training would be required to perform these
tasks on a manual basis due to the level of experience of its personnel and the
routine nature of the tasks being performed. The Company does not believe the
requirement for employees to perform tasks on a manual basis, in the event of
Year 2000 problems, would materially impact the Company's ability to continue
exploration, drilling, production or sales activities, although the tasks may
require additional time and personnel to complete the same function.
The Company's core business consists primarily of oil and gas acquisition,
development and exploration activities.
19
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
The equipment which is deemed "mission critical" to the Company's activities
requires external power sources such as electricity supplied by third parties.
Although the Company maintains limited on-site secondary power sources such as
generators, it is not economically feasible to maintain secondary power supplies
for any major component of its "mission critical" equipment. Therefore, the most
reasonably likely worst case Year 2000 scenario for the Company would involve a
disruption of third party supplied electrical power, which would result in a
substantial decrease in the Company's oil production. Such event could result in
a business interruption that could materially affect the Company's operations,
liquidity or capital resources.
The Company has had written communications with most of its significant
suppliers, business partners and key customers to determine the extent to which
the Company is vulnerable to either the third parties' or its own failure to
correct their Year 2000 issues. The Company has also been communicating with
such third parties to keep them informed of the Company's internal assessment of
its Year 2000 review and plans. To date, these third parties have provided
certain favorable representations as to their Year 2000 readiness and received
similar representations from the Company. There can be no guarantee that the
systems of other companies on which the Company relies will be timely converted
or that the conversion will be compatible with the Company's systems. However,
after reviewing and estimating the effects of such events, the Company's
contingency plan involves identifying and arranging for other vendors,
purchasers and third party contractors to provide such services, if necessary,
in order to maintain its normal operations. The Company has not incurred, and
does not anticipate that it will incur, any significant costs relating to the
assessment and remediation of Year 2000 issues.
Forward-Looking Information
The statements contained in this Quarterly Report on Form 10-Q ("Quarterly
Report") that are not historical facts, including, but not limited to,
statements found in this Management's Discussion and Analysis of Financial
Condition and Results of Operations, are forward-looking statements, as that
term is defined in Section 21E of the Securities and Exchange Act of 1934, as
amended, that involve a number of risks and uncertainties. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, acquisition plans and proposals and dispositions, development
activities, cost savings, production efforts and volumes, hydrocarbon reserves,
hydrocarbon prices, liquidity, regulatory matters and competition. Such
forward-looking statements generally are accompanied by words such as "plan,"
"estimate," "budgeted," "expect," "predict," "anticipate," "projected,"
"should," "assume," "believe" or other words that convey the uncertainty of
future events or outcomes. Such forward-looking information is based upon
management's current plans, expectations, estimates and assumptions and is
subject to a number of risks and uncertainties that could significantly affect
current plans, anticipated actions, the timing of such actions and the Company's
financial condition and results of operations. As a consequence, actual results
may differ materially from expectations, estimates or assumptions expressed in
or implied by any forward-looking statements made by or on behalf of the
Company. Among the factors that could cause actual results to differ materially
are: fluctuations of the prices received or demand for the Company's oil and
natural gas, the uncertainty of drilling results and reserve estimates,
operating hazards, acquisition risks, requirements for capital, general economic
conditions, competition and government regulations, as well as the risks and
uncertainties discussed in this Quarterly Report, including, without limitation,
the portions referenced above, and the uncertainties set forth from time to time
in the Company's other public reports, filings and public statements.
In assessing Year 2000 issues, the Company has relied on certain
representations of third parties and has attempted to predict and address all
possible scenarios which could arise. However, uncertainties exist which could
cause Year
20
<PAGE>
DENBURY RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
2000 effects to be more significant than the Company anticipates. Such
uncertainties include the success of the Company in identifying systems and
programs that are not Year 2000 compliant, the nature and amount of programming
required to up-grade or replace each of the affected programs, the availability,
rate and magnitude of related labor and consulting costs and the success of the
Company's vendors in addressing the Year 2000 issue.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
The information required by Item 3 is set forth under "Market Risk
Management" in Management's Discussion and Analysis of Financial Condition and
Results of Operations.
21
<PAGE>
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K during the Third Quarter of 1999
Exhibits:
10 Sixth amendment to the First Restated Credit Agreement dated
September 30, 1999 between the Company and Bank of America, N.A.,
as agent, and each of the financial institutions described on the
signature page therein.
27 Financial Data Schedule (EDGAR version only).
Reports on Form 8-K:
None
22
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DENBURY RESOURCES INC.
(Registrant)
By: /s/ Phil Rykhoek
-------------------------------
Phil Rykhoek
Chief Financial Officer
By: /s/ Mark C. Allen
-------------------------------
Mark C. Allen
Chief Accounting Officer & Controller
Date: November 9, 1999
23
EXHIBIT 10(a)
SIXTH AMENDMENT TO FIRST
RESTATED CREDIT AGREEMENT
<PAGE>
SIXTH AMENDMENT TO FIRST RESTATED CREDIT AGREEMENT
This Sixth Amendment to First Restated Credit Agreement (this "Sixth
Amendment") is entered into as of the 30th day of September, 1999 (the
"Effective Date"), by and among Denbury Resources, Inc. ("DRI"), a corporation
previously incorporated under the Canadian Business Corporation Act which has
been domesticated in the State of Delaware, Bank of America, N.A., successor by
merger to NationsBank, N.A., successor by merger to NationsBank of Texas, N.A.,
as Administrative Agent ("Agent"), and the financial institutions parties hereto
as Banks ("Banks").
W I T N E S S E T H:
WHEREAS, DRI, Agent and Banks are parties to that certain First Restated
Credit Agreement dated as of December 29, 1997, as amended by (a) that certain
First Amendment to First Restated Credit Agreement dated as of January 27, 1998,
(b) that certain Second Amendment to First Restated Credit Agreement dated as of
February 25, 1998, (c) that certain Third Amendment to First Restated Credit
Agreement dated as of August 10, 1998, (d) that certain Fourth Amendment to
First Restated Credit Agreement dated February 19, 1999, and (e) that certain
Fifth Amendment to First Restated Credit Agreement dated as of April 21, 1999
(as amended, the "Credit Agreement") (unless otherwise defined herein, all terms
used herein with their initial letter capitalized shall have the meaning given
such terms in the Credit Agreement); and
WHEREAS, pursuant to the Credit Agreement the Banks have made certain Loans
to DRI; and
WHEREAS, the parties desire to amend Section 9.15 of the Credit Agreement
in certain respects.
NOW THEREFORE, for and in consideration of the mutual covenants and
agreements herein contained and other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged and confessed, DRI,
Agent and each Bank hereby agree as follows:
Section 1. Amendment. Section 9.15 of the Credit Agreement is hereby
amended effective as of the Effective Date to read in full as follows:
"SECTION 9.15. Qualified Purpose. Borrower will not request or receive any
Borrowing hereunder if, after giving effect thereto and the use of the proceeds
thereof, that portion of the principal balance of the Revolving Loan which is
outstanding at such time and was utilized for any purpose other than a Qualified
Purpose exceeds twenty five percent (25%) of the Conforming Borrowing Base in
effect at such time. Borrower agrees that each Request for Borrowing will
include, in addition to the information described in Section 2.2 hereof, a
10 - 1
<PAGE>
certification from an Authorized Officer of Borrower as to the purpose and
utilization of the proceeds of such Borrowing. Additionally, notwithstanding
anything to the contrary contained in Section 3.2 hereof, all principal payments
received by Banks with respect to the Revolving Loan shall be applied first to
that portion of the outstanding principal balance of the Revolving Loan utilized
for purposes other than Qualified Purposes. Notwithstanding the foregoing, the
Credit Parties shall not be required to comply with this Section 9.15 at any
time (a) on or prior to the date Texas Pacific Group makes the Proposed Equity
Contribution (and Parent, in turn, contributes the proceeds of such Proposed
Equity Contribution to the common equity capital of Borrower), and (b) that the
Borrowing Base is equal to the Conforming Borrowing Base. Any principal
outstanding under the Revolving Loan immediately after giving effect to receipt
and application of the proceeds of the Proposed Equity Contribution (as required
pursuant to Section 2.6) shall be deemed to be utilized for a Qualified
Purpose."
Section 2. Miscellaneous.
2.1 Reaffirmation of Loan Papers; Extension of Liens. Any and all of the
terms and provisions of the Credit Agreement and the Loan Papers shall, except
as amended and modified hereby, remain in full force and effect. DRI hereby
extends the Liens securing the Obligations until the Obligations have been paid
in full or are specifically released by Agent and Banks prior thereto, and
agrees that the amendments and modifications herein contained shall in no manner
adversely affect or impair the Obligations or the Liens securing payment and
performance thereof.
2.2 Parties in Interest. All of the terms and provisions of this Sixth
Amendment shall bind and inure to the benefit of the parties hereto and their
respective successors and assigns.
2.3 Legal Expenses. DRI hereby agrees to pay on demand all reasonable fees
and expenses of counsel to Agent incurred by Agent, in connection with the
preparation, negotiation and execution of this Sixth Amendment and all related
documents.
2.4 Counterparts. This Sixth Amendment may be executed in counterparts, and
all parties need not execute the same counterpart; however, no party shall be
bound by this Sixth Amendment until all parties have executed a counterpart.
Facsimiles shall be effective as originals.
2.5 Complete Agreement. THIS SIXTH AMENDMENT, THE CREDIT AGREEMENT AND THE
OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE
PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.
10 - 2
<PAGE>
2.6 Headings. The headings, captions and arrangements used in this Sixth
Amendment are, unless specified otherwise, for convenience only and shall not be
deemed to limit, amplify or modify the terms of this Sixth Amendment, nor affect
the meaning thereof.
IN WITNESS WHEREOF, the parties hereto have caused this Sixth Amendment to
be duly executed by their respective authorized officers on the date and year
first above written.
BORROWER:
DENBURY RESOURCES, INC.,
a Delaware corporation
By:
--------------------------------
Gareth Roberts
President and Chief Executive
Officer
By:
--------------------------------
Phil Rykhoek
Chief Financial Officer and
Secretary
ADMINISTRATIVE AGENT:
BANK OF AMERICA, N.A.,
By:
---------------------------------
J. Scott Fowler,
Managing Director
BANKS:
BANK OF AMERICA, N.A.,
By:
---------------------------------
J. Scott Fowler,
Managing Director
10 - 3
<PAGE>
BANKBOSTON, N.A.
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
BANK ONE, TEXAS, N.A.
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
CHRISTIANIA BANK, OG KREDITKASSE ASA
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
PARIBAS
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
CREDIT LYONNAIS - NEW YORK BRANCH
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
10 - 4
<PAGE>
WELLS FARGO BANK (TEXAS), N.A.
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
NATEXIS BANQUE BFCE
By:
---------------------------------
Name:
---------------------------------
Title:
---------------------------------
10 - 5
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMAITON EXTRACTED FROM THE DENBURY
RESOURCES INC. SEPTEMBER 30, 1999 FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000945764
<NAME> DENBURY RESOURCES INC
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<EXCHANGE-RATE> 1
<CASH> 6,499
<SECURITIES> 0
<RECEIVABLES> 17,829
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 24,278
<PP&E> 615,097
<DEPRECIATION> 410,694
<TOTAL-ASSETS> 239,439
<CURRENT-LIABILITIES> 17,403
<BONDS> 152,500
0
0
<COMMON> 46
<OTHER-SE> 67,358
<TOTAL-LIABILITY-AND-EQUITY> 239,439
<SALES> 54,601
<TOTAL-REVENUES> 55,670
<CGS> 0
<TOTAL-COSTS> 43,633
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<INTEREST-EXPENSE> 12,170
<INCOME-PRETAX> (133)
<INCOME-TAX> 0
<INCOME-CONTINUING> (133)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (133)
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00
</TABLE>
